Fluid streams derived from natural gas reservoirs, petroleum or coal, often contain a significant amount of acid gases, for example carbon dioxide (CO2), hydrogen sulfide (H2S), sulfur dioxide (SO2), carbon disulfide (CS2), hydrogen cyanide (HCN), carbonyl sulfide (COS), or mercaptans as impurities. Said fluid streams may be gas, liquid, or mixtures thereof, for example gases such as natural gas, refinery gas, hydrocarbon gasses from shale pyrolysis, synthesis gas, and liquids such as liquefied petroleum gas (LPG) and natural gas liquids (NGL).
Various compositions and processes for removal of acid gasses are known and described in the literature. It is well-known to treat gaseous mixtures with aqueous amine solutions to remove these acidic gases. Typically, the aqueous amine solution contacts the gaseous mixture comprising the acidic gases counter currently at low temperature and high pressure in an absorber tower. The aqueous amine solution commonly contains an alkanolamine such as triethanolamine (TEA), methyldiethanolamine (MDEA), diethanolamine (DEA), monoethanolamine (MEA), diisopropanolamine (DIPA), or 2-(2-aminoethoxy)ethanol (sometimes referred to as diglycolamine or DGA). In some cases, an accelerator, is used in combination with the alkanolamines, for example piperazine and MDEA as disclosed in U.S. Pat. Nos. 4,336,233; 4,997,630; and 6,337,059. Alternatively, EP 0134948 discloses mixing an acid with select alkaline materials such as MDEA, to provide enhanced acid gas removal. However, EP0134948 teaches that only a select class of alkaline materials mixed with an acid is useable in aqueous alkaline solutions to provide increased acid gas removal.
Tertiary amines, such as 3-dimethylamino-1,2-propanediol (DMAPD), have been shown to be effective at removing CO2 from gaseous mixtures, see U.S. Pat. No. 5,736,116 or DMAPD in conjunction with piperazine, see WO2014/004019, or DMAPD in conjunction with an acid, see WO 2014/004020. Further, in specific processes, e.g., the Girbotol Process, tertiary amines have been shown effective in removal of H2S, but show decreased capacity at elevated temperatures, for examples see “Organic Amines-Girbotol Process”, Bottoms, R. R., The Science of Petroleum, volume 3, Oxford University Press, 1938, pp 1810-1815.
While the above compounds are effective, they each have limitations which detract from their universal use. In particular, it would be desirable to have an aqueous composition comprising an alkanolamine for removing H2S from a gaseous mixture and/or an aqueous alkanolamine solution which is efficient at removing acid gases at a commercially viable capacity when the aqueous solution is used at an elevated temperature, for example above 140° F.
As such, there is a need for an aqueous alkanolamine solution and method to use said solution, which is effective at removing hydrogen sulfide from gaseous mixtures and/or removing hydrogen sulfide at elevated operating temperatures.